Consolidated material to equalize fluid flow into a wellbore

ABSTRACT

Methods for equalizing flow into a wellbore using consolidated material are described. An unconsolidated material and a consolidation fluid are flowed into a wellbore formed in a hydrocarbon-bearing subterranean zone, and a permeability of the subterranean zone to flow fluid through the subterranean zone into the wellbore is non-uniform across an axial length of the wellbore. The unconsolidated material and the consolidation fluid are contacted across at least an axial segment of an inner surface of the wellbore, and the unconsolidated material is bound with the consolidated fluid to form a pack, in which the pack has a permeability that is more uniform than the permeability of the subterranean zone. A flow of fluids from the axial segment of the subterranean zone into the wellbore is controlled through the pack.

CROSS-REFERENCE TO RELATED PATENT APPLICATIONS

This application is a continuation of and claims the benefit of priorityto U.S. patent application Ser. No. 15/827,262, filed Nov. 30, 2017, thecontents of which are incorporated by reference herein.

TECHNICAL FIELD

This specification relates to equalizing fluid flow into a wellborepenetrating a subterranean formation, using consolidated material, forexample, as a flow choking mechanism.

BACKGROUND

Permeability is the ability of a material to transmit fluid. In relationto hydrocarbon recovery, rock permeability is one of the variousparameters utilized to characterize a hydrocarbon-bearing reservoir andto predict the reservoir's productivity and profitability. When a singlefluid is present in a formation, an absolute permeability can bemeasured, for example, in millidarcy (mD). When two or more immisciblefluids are present in a formation (as is usually the case), each fluidaffects the ability of the other fluids to flow. In such cases, theeffective permeability is the ability to preferentially transmit aparticular fluid in the presence of other fluids, and the relativepermeability is the ratio of the effective permeability of theparticular fluid at a certain saturation to the absolute permeability ofthat fluid at total saturation.

To further complicate hydrocarbon extraction from a reservoir,permeability is not typically distributed uniformly. Rather, rockformations are typically complex, heterogeneous, and anisotropic—thatis, rock formations usually have varied geometry and permeability acrossdifferent locations within the formation. The magnitude of permeabilitycontrast can have significant impact on production. For example, a layerof low permeability can impede the downward movement of hydrocarbon gas,whereas a layer of high permeability can prematurely bring undesiredwater to a production well (referred to as water breakthrough). Wellscan be completed such that the effect of the formation's heterogeneityon production is mitigated. For example, well completions can aim toevenly distribute inflow of fluids.

SUMMARY

The present disclosure describes technologies relating to equalizingflow into a wellbore penetrating a subterranean formation, usingconsolidated material.

Certain aspects of the subject matter described here can be implementedas a method. An unconsolidated material and a consolidation fluid areflowed into a wellbore formed in a hydrocarbon-bearing subterraneanzone, and a permeability of the subterranean zone to flow fluid throughthe subterranean zone into the wellbore is non-uniform across an axiallength of the wellbore. The unconsolidated material and theconsolidation fluid are contacted across at least an axial segment of aninner surface of the wellbore, and the unconsolidated material is boundwith the consolidation fluid to form a pack, in which the pack has apermeability that is more uniform than the permeability of thesubterranean zone. A flow of fluids from the axial segment of thesubterranean zone into the wellbore is controlled through the pack.

This, and other aspects, can include one or more of the followingfeatures. The consolidation fluid can include a resin and a curingagent.

The unconsolidated material can include sand, ceramic proppants, orcombinations of them.

The consolidation fluid can bind the unconsolidated material aftercontacting the pack across at least the axial segment of the innersurface of the wellbore.

The pack can be contacted with a postflush fluid to increase thepermeability of the pack after contacting the pack across at least theaxial segment of the inner surface of the wellbore.

The postflush fluid can include an aqueous fluid, a solvent, orcombinations of them.

The postflush fluid can include methanol, water, or combinations ofthem.

The pack can be left to harden for substantially 48 hours or less aftercontacting the pack with the postflush fluid.

The permeability of the pack after contacting the pack with thepostflush fluid can be substantially 80% or less of a permeability ofthe unconsolidated material.

Certain aspects of the subject matter described here can be implementedas a method for completing a well. An unconsolidated material is flowedinto a wellbore formed in a hydrocarbon-bearing subterranean zone, inwhich a permeability of the subterranean zone to flow fluid through thesubterranean zone into the wellbore varies across an axial length of thewellbore; a consolidation fluid is flowed into the wellbore; theunconsolidated material is at least partially consolidated within thewellbore using the consolidating fluid to form an at least partiallyconsolidated material having a permeability that is different from thepermeability of the subterranean zone, in which the at least partiallyconsolidated material coats an inner wall of an axial segment of thewellbore; and a flow of fluids from the axial segment of thesubterranean zone into the wellbore is controlled through the at leastpartially consolidated material.

This, and other aspects, can include one or more of the followingfeatures. The consolidation fluid can include a resin and a curingagent.

The unconsolidated material can include sand, ceramic proppants, orcombinations of them.

The consolidation fluid and the unconsolidated material can be flowedtogether into the wellbore.

The consolidation fluid can be flowed into the wellbore after flowingthe unconsolidated material into the wellbore.

The at least partially consolidated material can be contacted with apostflush fluid to increase the permeability of the at least partiallyconsolidated material.

The postflush fluid can include an aqueous fluid, a solvent, orcombinations of them.

The postflush fluid can include methanol, water, or combinations ofthem.

The at least partially consolidated material can be contacted with thepostflush fluid to increase permeability, and the at least partiallyconsolidated material can be left to harden for substantially 48 hoursor less.

The permeability of the at least partially consolidated material aftercontacting the at least partially consolidated material with thepostflush fluid can be substantially 80% or less of a permeability ofthe unconsolidated material.

The details of one or more implementations of the subject matter of thisspecification are set forth in the accompanying drawings and thedescription. Other features, aspects, and advantages of the subjectmatter will become apparent from the description, the drawings, and theclaims.

DESCRIPTION OF DRAWINGS

FIG. 1A is an example of a well in a fractured formation.

FIG. 1B is an example of the well of FIG. 1A, which includesunconsolidated material.

FIG. 1C is an example of the well of FIG. 1A, which includesconsolidated material.

FIG. 1D is an example of the well of FIG. 1A, which includesconsolidated material.

FIG. 2 is a flow chart of a method for controlling fluid flow into awellbore.

FIG. 3 is a flow chart of a method for controlling fluid flow into awellbore.

DETAILED DESCRIPTION

A subterranean zone—which can be a formation, a portion of a formation,or multiple formations in a hydrocarbon-bearing reservoir—can havevaried or heterogeneous permeability (that is, the permeability can bedifferent across various areas of the subterranean zone). Levels ofpermeability (for example, high, moderate, and low) can be defined on abasis of both the permeability of the formation and the viscosity of thefluid being produced. For example, in the case of a gas well with anaverage viscosity of 0.02 centipoise (cP) of hydrocarbon gas, apermeability of 0.1 millidarcy (mD) or less can be considered low, apermeability between 1 mD and 10 mD can be considered moderate, and apermeability greater than 25 mD can be considered high. As anotherexample, in the case of an oil well with an average viscosity of 2 cP ofhydrocarbon oil, a permeability of 10 mD or less can be considered low,a permeability between 100 mD and 1,000 mD can be considered moderate,and a permeability greater than 2,500 mD can be considered high.Carbonate reservoirs typically have a high degree of fracturing andpermeability variation. In some cases, heterogeneous reservoirs havethin stratigraphic sequences of high permeability, while the rest of theformation has low permeability. The thin stratigraphic sequences of highpermeability are also known as high permeability streaks. For a wellboreformed in a subterranean zone, heterogeneous permeability and thepresence of high permeability streaks can cause the flow distribution(or inflow profile) along the length of the wellbore to be non-uniform.An uneven fluid flow distribution into a well installed in such awellbore can cause various production issues. For example, uneven inflowprofiles can lead to (and accelerate) water or gas coning and subsequentbreakthrough, which can possibly prematurely end the well's productivelife and leave valuable hydrocarbons unrecovered from the subterraneanzone. Inflow control devices (ICDs) are pieces of passive, permanenthardware that can be installed at various points along a well topartially choke flow (that is, provide additional pressure drop) for thepurpose of achieving a more uniform flow distribution of fluids into thewellbore. ICDs can be, for example, nozzles, orifices, tubes, or helicalchannels and can be expensive to purchase and install.

Sometimes, consolidated material, for example, consolidated sand orother consolidated material, can be used as an alternative to ICDs.Consolidated material can be more cost effective than conventional ICDs,as consolidated material can be installed without the need of a rig, andthe base material of consolidated material can be less expensive thanthose for ICDs. In some cases, consolidated material can be more durablethan ICDs. Consolidated material can also be chemically altered, forexample, the consolidated material can be treated to increase ordecrease the permeability of the consolidated material in cases wherewell conditions change.

This disclosure describes technologies relating to creating a layer ofconsolidated material with uniform permeability within a wellbore forthe purpose of controlling fluid flow into the wellbore. In other words,the consolidated material can serve a similar function as inflow controldevices and can therefore replace inflow control devices. In thisspecification, “uniform” means having a ratio of a maximum value to aminimum value less than 5. For example, if a portion of material has aminimum permeability of 100 millidarcy (mD) and a maximum permeabilityof 400 mD (ratio of maximum to minimum is 4), then the portion ofmaterial can be considered to have uniform permeability. Conversely, ifa portion of material has a minimum permeability of 200 mD and a maximumpermeability of 1,100 mD (ratio of maximum to minimum is 5.5), then thatportion of material can be considered to have a non-uniformpermeability. Additionally, in a comparison, “more uniform” means havinga ratio of a maximum value to a minimum value closer to 1. For example,if a portion of a first material has a minimum permeability of 100 mDand a maximum permeability of 200 mD (ratio of maximum to minimum of 2),and a portion of a second material has a minimum permeability of 250 mDand a maximum permeability of 750 mD (ratio of maximum to minimum of 3),then the portion of the first material can be considered to have a moreuniform permeability than the portion of the second material. Byimplementing the techniques described here, the effects of highpermeability streaks or fractures in a subterranean zone can bemitigated or eliminated. The fluid flow into a wellbore formed in asubterranean zone can be equalized, and the equalized flow distributioncan delay water breakthrough and prematurely ending production. In somecases, the consolidation treatment of the subterranean zone introducesmaterial into an annulus between completion tubing and the inner surfaceof a wellbore, such that drill out after material consolidation is notrequired.

FIG. 1A shows a system 100A which includes a well within a wellboreformed in a subterranean zone. While the well shown in FIG. 1A is ahorizontal well, the well can be vertical, angled, branched or acombination of them. The well can include or not include a productioncasing, liner, or tubing 101 that extends into the wellbore. In someimplementations, the well can be open hole, which can be more costeffective than a cased hole. In some implementations, the well can bepartially cased. The wellbore can have a surface 150, and fluid can flowfrom the subterranean zone into the wellbore and up to the surfacethrough the production tubing 101. The subterranean zone can be, forexample, a carbonate or sandstone formation that is fractured and hasheterogeneous permeability (depicted by the various patterning in FIG.1A) along an axial length of the wellbore. Without additional treatment,fluid inflow to the well can potentially be unevenly distributed due tothe varied permeability profile of the subterranean zone.

FIG. 1B shows a system 100B that is similar to system 100A, but includesunconsolidated material 120B. Unconsolidated material 120B can beintroduced to the wellbore and can contact the surface 150 of thewellbore. For example, the unconsolidated material 120B can be pumpeddownhole in the form of a slurry through the well. In someimplementations, the unconsolidated material 120B can travel down thewell and exit the casing 101 through perforations, for example, theperforations utilized to hydraulically fracture the subterranean zone.In some implementations, the unconsolidated material 120B is pumpeddownhole to a targeted location through coiled tubing. Theunconsolidated material 120B can contact the surface 150 of thewellbore. In some implementations, the unconsolidated material 120B atleast partially fills an annulus between the surface 150 of the wellboreand the casing 101. In some implementations, both sides of a targetedaxial portion of the wellbore are cemented, so that material flows onlyto the targeted area. As one example, for a vertical well, an upholeside and a downhole side of the targeted axial portion of the wellboreare cemented, so that material flows only to the targeted area betweenthe two cemented sides. In some implementations, the unconsolidatedmaterial 120B can also serve as a proppant and help keep theperforations (that is, fractures) open and therefore prevent re-healingof the fractures. Unconsolidated material 120B can be a naturallyoccurring material or a manmade material. Examples of unconsolidatedmaterial 120B include sand, date seed material, and ceramic proppants.The unconsolidated material 120B can be made of a material that canwithstand the high subsurface pressures and temperatures associated withthe subterranean zone, for example, temperatures ranging betweenapproximately 100 degrees Fahrenheit (° F.) and 400° F. and pressureranging between approximately 1,000 pounds per square inch gauge (psig)and 10,000 psig. The size of the individual particles of theunconsolidated material 120B can be uniform or varied and can depend ona desired permeability. In turn, the desired permeability can depend onthe permeability range of the target area of the subterranean zone. Theparticles of the unconsolidated material 120B can have any shape, suchas spherical, faceted, or irregular.

A consolidation fluid that can bind the unconsolidated material can alsobe introduced to the wellbore. For example, the consolidation fluid canbe pumped downhole through the well. In some implementations, theconsolidation fluid can travel down the well and exit the casing 101through perforations, for example, the perforations utilized tohydraulically fracture the subterranean zone. In some implementations,the consolidation fluid is pumped downhole to a targeted locationthrough coiled tubing. The consolidation fluid can contact theunconsolidated material 120B within the wellbore. The consolidationfluid can occupy space between particles of unconsolidated material120B. In some implementations, the consolidation fluid surrounds theparticles of unconsolidated material 120B up to a distance outside thecasing 101 equal to an outer diameter of the casing 101. Theconsolidation fluid can include a resin that is compatible with thesubterranean zone and the fluids that already exist within thesubterranean zone. A resin is a liquid capable of hardening and aretypically viscous. An example of a suitable resin is a synthetic resin,such as an epoxy resin or a polyurethane resin. In some cases, thesubsurface temperature of the subterranean zone can cause theconsolidation fluid to harden—which is the case, for example, for athermosetting polymer. A thermosetting polymer (also referred asthermosetting plastic, thermoset, or thermosetting resin) is a polymerthat can be irreversibly hardened from a liquid or resin that istypically viscous prior to hardening. A thermosetting polymer can behardened by action of heat, radiation, or by mixing with a catalyst.Curing a thermosetting resin irreversibly transforms the resin into aplastic or elastomer by crosslinking or chain extension. In thisdocument, the term “harden” should be interpreted in a flexible mannerto include any form of hardening, such as curing (in the case of a resinor polymer) or solidifying. In some cases, the consolidation fluidincludes a curing agent that can cause the consolidation fluid toharden. A curing agent is a substance that causes hardening of a resin.In some cases, the resin begins to harden once the resin is in contactwith the curing agent. In some cases, the resin begins to harden once itis exposed to an elevated temperature (for example, 200° F.) after theresin and the curing agent have made contact. A few examples of curingagents are cyclic anhydrides, polyphenols, polyfunctional primaryamines, tertiary amines, furan, unsaturated polyester-vinylpyrrolidone,unsaturated polyester-styrene, or combinations of these. For example,the consolidation fluid can include two monomers in a copolymer with onemonomer being the resin and the other monomer being the curing agent orhardener. In such cases, the two monomers can unite (that is, undergo alinking reaction) to polymerize into a hardened compound. The hardeningof the consolidation fluid can consolidate (that is, connect or bind)the unconsolidated material together. In other words, the consolidationfluid can harden to form a matrix that secures, connects, or binds theunconsolidated material together. In certain implementations, theunconsolidated material 120B is introduced simultaneously with theconsolidation fluid. In some implementations, the consolidation fluid ismixed with the unconsolidated material 120B at a surface location, andthe mixture is introduced to the wellbore. For example, the mixture ofconsolidation fluid and unconsolidated material 120B can be a slurry ofsolids entrained in a liquid, and the slurry can be pumped downhole to atargeted location through coiled tubing. In certain implementations, theconsolidation fluid is introduced to the wellbore after theunconsolidated material 120B. The well can be shut in for sufficienttime to at least partially consolidate the unconsolidated material 120Bwith the consolidation fluid. For example, the well can be shut in forsubstantially 48 hours or less, so that the consolidation fluid canharden, thereby consolidating the unconsolidated material 120B. In thisspecification, “substantially” means a deviation or allowance of up to10 percent (%).

FIG. 1C shows a system 100C that is similar to system 100B, but withconsolidated material 120C after the unconsolidated material 120B hasbeen at least partially consolidated by the consolidation fluid. Theconsolidated material 120C can contact the surface 150 of the wellbore.The wellbore can have an inner diameter. In the case where the wellboreis completed open hole, the consolidated material 120C can have athickness that is substantially equal to one third of the inner diameterof the wellbore or less. The amount of consolidation fluid andunconsolidated material 120B introduced to the well can depend on anestimated or desired final volume of consolidated material 120C withinthe wellbore after the consolidation fluid has hardened and consolidatedthe unconsolidated material 120B. The thickness of the consolidatedmaterial 120C can also be controlled by slotted liners that can beplaced and left within the well. The consolidated material 120C can havea uniform permeability. The consolidated material 120C can have apermeability that is more uniform than the subterranean zone along anaxial length of the wellbore. The consolidated material 120C can have alower permeability than the unconsolidated material 120B.

FIG. 1D shows a system 100D that is similar to system 100C, but withtreated consolidated material 120D with higher permeability that theconsolidated material 120C. A postflush fluid can be introduced to thewellbore. The postflush fluid can be an aqueous fluid, a solvent, or acombination of both. In certain implementations, the postflush fluid ismethanol, water, or a mixture of both. The postflush fluid can contactthe consolidated material 120C. In some cases, the postflush fluiddissolves any unhardened consolidation fluid. The postflush fluid candissolve a portion of the hardened consolidated material 120C. In thisway, the postflush fluid can cause the permeability of the consolidatedmaterial 120C to increase. The postflush fluid can interact with theconsolidated material 120C to produce the treated consolidated material120D with increased permeability. The amount of postflush fluid utilizedcan depend on the volume of unconsolidated material 120B andconsolidation fluid (therefore, the volume of consolidated material120C) introduced to the well. Increasing the amount of postflush fluidutilized can increase the permeability of the treated consolidatedmaterial 120D. The well can be shut in, so that the postflush fluidcontacts the consolidated material 120C for sufficient time to increasepermeability, for example, 48 hours or less. In some cases, thepostflush fluid is introduced to the wellbore immediately afterintroducing the unconsolidated material 120B and consolidation fluid,and then the well is shut in for 48 hours or less. In certainimplementations, the permeability of the treated consolidated material120D (after postflush fluid treatment) is substantially 80% (or less) ofthe permeability of the unconsolidated material 120B (beforeconsolidation). The treated consolidated material 120D after contactwith the postflush fluid can have a uniform permeability (similar to theconsolidated material 120C). The treated consolidated material 120D canhave permeability that is more uniform than the subterranean zone alongan axial length of the wellbore (similar to the consolidated material120C). The treated consolidated material 120D can serve as a choke (thatis, increase pressure drop) to regulate fluid flow into the well.Because the treated consolidated material 120D has a uniformpermeability, the distribution of flow into the wellbore (and the well)can be equalized along the axial length of the wellbore. The uniform,equal distribution can delay, mitigate, or prevent such things as waterbreakthrough. In the case with sandstone formations, the consolidatedmaterial can also delay, mitigate, or prevent undesirable sandproduction. A production log can be recorded before and after theconsolidation treatment. The production log can include a flow profileof fluids across the well and a percentage of flow reduction comparingbefore and after the consolidation treatment as a measure of chokingeffect that the treated consolidated material 120D provides. Theproduction log can include a comparison of pressure build up before andafter the consolidation treatment as another way to measure the chokingeffect of the treated consolidated material 120D. As one example,analysis of a well test can provide insight on the added layer oftreated consolidated material 120D, as the treated consolidated material120D will appear as a skin in the analysis. Although the postflush fluidincreases permeability of the consolidated material 120B (which isbeneficial), the postflush fluid also decreases the strength orcompetency of the consolidated material 120C (which is detrimental). Theamount of postflush fluid introduced to the wellbore and the duration ofwell shut in should be carefully planned, such that the desired chokingeffect is achieved, while also maintaining an end product (that is, thetreated consolidated material 120D) that is not prone to breaking,eroding, or ripping away from the wellbore surface when productionfluids flow through the treated consolidated material 120D. The treatedconsolidated material 120D can be sufficiently competent (that is,strong enough) to resist erosion effects of any production fluidsflowing from the subterranean zone into the wellbore, through thetreated consolidated material 120D.

FIG. 2 is a flow chart of a method 200 for controlling fluid flow into awellbore. At 201, an unconsolidated material and a consolidation fluidare flowed into a wellbore formed in a hydrocarbon-bearing subterraneanzone. The subterranean zone has a permeability to flow fluid through thesubterranean zone into the wellbore. The permeability of thesubterranean zone is non-uniform across an axial length of the wellbore.The wellbore can be vertical, horizontal, angled, branched, or acombination of them. For example, the unconsolidated material can besand, ceramic proppants, or a combination of these materials, and theconsolidation fluid can include a resin and a curing agent. In someimplementations, the unconsolidated material and the consolidated fluidare mixed at a surface location to form a slurry before being flowedinto the wellbore. Before the unconsolidated material and theconsolidation fluid is flowed into the wellbore (201), the subterraneanzone can be pre-flushed, for example, with diesel to mobilize fluidssuch as oil or water away from the wellbore into the formation, so thatthese fluids do not affect or interfere with the pack.

At 203, the unconsolidated material and the consolidation fluid arecontacted across at least an axial segment of an inner surface of thewellbore. The production casing within the wellbore can have an outerdiameter. The unconsolidated material and the consolidation fluid thatare contacted across the axial segment of the inner surface of thewellbore can have a thickness that is substantially half the outerdiameter of the casing or less.

At 205, the consolidation fluid binds the unconsolidated material toform a pack. The pack has a permeability that is more uniform than thepermeability of the subterranean zone, for example, the matrixpermeability of the formation. In some cases, the pack is contacted witha postflush fluid to increase the permeability of the pack. Thepostflush fluid can include an aqueous fluid, a solvent, or acombination of both. In certain implementations, the postflush fluid ismethanol, water, or a combination of both. The pack can be contactedwith the postflush fluid and can be left to harden for substantially 48hours or less. After the pack is contacted with the postflush, thepermeability of the pack can be substantially 80% (or less) of theoriginal permeability of the unconsolidated material.

At 207, a flow of fluids from the axial segment of the subterranean zoneinto the wellbore is controlled through the pack. Because the pack has auniform permeability, the pack can serve as a choke, thereby equalizingthe flow of fluids from the subterranean formation into the wellborealong a length of the wellbore. Without the pack (or other device toequalize inflow), the heterogeneous (that is, non-uniform) permeabilityof the subterranean zone can cause flow to preferentially flow throughhigher permeability areas along the wellbore, meaning some areas of thewellbore may experience higher inflow rates in comparison to other areaswith lower permeability, which can lead to undesirable premature waterbreakthrough.

FIG. 3 is a flow chart of a method 300 for controlling fluid flow into awellbore. At 301, an unconsolidated material is flowed into a wellboreformed in a hydrocarbon-bearing subterranean zone. The subterranean zonehas a permeability to flow fluid through the subterranean zone into thewellbore. The permeability of the subterranean zone varies across anaxial length of the wellbore. Similar to method 200, the unconsolidatedmaterial can be sand, ceramic proppants, or a combination of thesematerials.

At 303, a consolidation fluid is flowed into the wellbore. Theconsolidation fluid and the unconsolidated material can be flowedtogether into the wellbore (in other words, 301 and 303 can occursimultaneously). For example, the consolidation fluid and theunconsolidated material can be flowed into the wellbore at the sametime. As another example, the consolidation fluid and the unconsolidatedmaterial can be mixed to form a slurry, and the slurry of theconsolidation fluid and the unconsolidated material can be flowed intothe wellbore. In certain implementations, the consolidation fluid isflowed into the wellbore after flowing the unconsolidated material intothe wellbore (in other words, 303 occurs after 301). The consolidationfluid and the unconsolidated material can be pumped downhole into thewellbore, for example, as a slurry.

At 305, the unconsolidated material is at least partially consolidatedwithin the wellbore using the consolidating fluid to form an at leastpartially consolidated material. Consolidating the unconsolidatedmaterial using the consolidating fluid can involve connecting or bindingthe unconsolidated material together to form a larger, consolidatedmass. Similar to method 200, the consolidation fluid can include a resinand a curing agent. The consolidated material has a permeability that isdifferent from the permeability of the subterranean zone, and thepartially consolidated material coats an inner wall of an axial segmentof the wellbore. The consolidated material can have a permeability thatis more uniform than the permeability of the subterranean zonesurrounding the wellbore. In certain implementations, the at leastpartially consolidated material is contacted with a postflush fluid toincrease the permeability of the at least partially consolidatedmaterial. The postflush fluid can include an aqueous fluid, a solvent,or a combination of both. In certain implementations, the postflushfluid is methanol, water, or a combination of both. The at leastpartially consolidated material can be left to harden for substantially48 hours or less to continue hardening after the postflush treatment.After the at least partially consolidated material is contacted with thepostflush fluid, the permeability of the at least partially consolidatedmaterial can be substantially 80% (or less) of the original permeabilityof the unconsolidated material.

At 307, a flow of fluids from the axial segment of the subterranean zoneinto the wellbore is controlled through the at least partiallyconsolidated material. The at least partially consolidated material canhave a uniform permeability and can serve as a choke, thereby equalizingthe flow of fluids from the subterranean formation into the wellborealong a length of the wellbore. Without the partially consolidatedmaterial (or other device to equalize inflow), the heterogeneous (thatis, non-uniform) permeability of the subterranean zone can cause flow topreferentially flow through higher permeability areas along thewellbore, meaning some areas of the wellbore may experience higherinflow rates in comparison to other areas with lower permeability, whichcan lead to undesirable premature water breakthrough.

Example

Experiments were conducted on loose sand (unconsolidated material)collected from Unayzah formation. The sand was consolidated with a resinincluding a curing agent (EXPEDITE® A&B by Halliburton Energy Services,Inc.) and flushed with a methanol solvent (postflush fluid) to increasepermeability. The sand was packed into a plug-like core holder and wasflooded with the resin (that is, the resin was injected at one end ofthe sand pack such that the resin floods and flows through the sandpack) under reservoir conditions (3,500 psig and 194° F.) to simulatedownhole conditions of injecting the resin into a sandstone formation tostabilize the formation. The methanol solvent was pure methanol, and atleast two pore volumes were injected through the consolidated sand core.The result was a mechanically competent sand pack with a permeability ofnearly 70% of the original permeability of the loose sand. Core floodingtests were conducted on the consolidated sand pack. Throughout thetests, a temperature of substantially 194° F. and a pressure ofsubstantially 3,500 psig were maintained to simulate subterraneanreservoir conditions.

Prior to resin treatment, the sand pack was pre-flushed with diesel at arate of 3 cubic centimeters per minute (cc/min) for at least two porevolumes. An initial permeability of the loose sand pack to a syntheticbrine solution of 3% potassium chloride (KCl) was measured. Permeabilitywas calculated per Darcy's law:

${= \frac{Q\;\mu\; L}{\left( {P_{u} - P_{d}} \right)A}},$where k is permeability, Q is the fluid injection rate through the sandpack, μ is the viscosity of the injected fluid (brine), L is the lengthof the sand pack, P_(u) is the pressure upstream of the sand pack, P_(d)is the pressure downstream of the sand pack, and A is thecross-sectional area of the sand pack (perpendicular to the direction ofinjected flow). The permeability was measured at multiple injectionrates varying from approximately 3 cc/min to approximately 6 cc/min forat least two pore volumes. The permeability of the loose sand packstabilized between approximately 50 mD to approximately 55 mD.

The sand pack was then consolidated with the resin, followed by apostflush treatment of methanol. The sand pack was then shut in for 48hours at approximately 194° F. After the shut in, the permeability ofthe consolidated sand pack (treated with postflush fluid to increasepermeability) was measured over 7 days of continuous brine injection(the same brine solution used previously in measuring the permeabilityof the loose sand pack) at approximately 3 cc/min to 6 cc/min. Theaverage permeability was maintained at approximately 35 mD, which isapproximately 70% of the original permeability of the loose (that is,unconsolidated) sand pack.

While this specification contains many specific implementation details,these should not be construed as limitations on the scope of anyinvention or on the scope of what may be claimed, but rather asdescriptions of features that may be specific to particularimplementations of particular inventions. Certain features that aredescribed in this specification in the context of separateimplementations can also be implemented, in combination, in a singleimplementation. Conversely, various features that are described in thecontext of a single implementation can also be implemented in multipleimplementations, separately, or in any suitable sub-combination.Moreover, although previously described features may be described asacting in certain combinations and even initially claimed as such, oneor more features from a claimed combination can, in some cases, beexcised from the combination, and the claimed combination may bedirected to a sub-combination or variation of a sub-combination.

Particular implementations of the subject matter have been described.Other implementations, alterations, and permutations of the describedimplementations are within the scope of the following claims as will beapparent to those skilled in the art. While operations are depicted inthe drawings or claims in a particular order, this should not beunderstood as requiring that such operations be performed in theparticular order shown or in sequential order, or that all illustratedoperations be performed (some operations may be considered optional), toachieve desirable results.

Accordingly, the previously described example implementations do notdefine or constrain this disclosure. Other changes, substitutions, andalterations are also possible without departing from the spirit andscope of this disclosure.

What is claimed is:
 1. A method comprising: flowing an unconsolidatedmaterial and a consolidation fluid into a wellbore formed in ahydrocarbon-bearing subterranean zone; binding the unconsolidatedmaterial with the consolidation fluid to form a pack; after binding theunconsolidated material with the consolidation fluid, dissolving atleast a portion of the pack with a postflush fluid to increasepermeability of the pack; and after dissolving at least a portion of thepack with the postflush fluid, equalizing a flow of fluids through thepack.
 2. The method of claim 1, wherein the consolidation fluidcomprises a resin and a curing agent.
 3. The method of claim 1, whereinthe unconsolidated material comprises sand, ceramic proppants, orcombinations thereof.
 4. The method of claim 1, wherein the postflushfluid comprises an aqueous fluid, a solvent, or combinations thereof. 5.The method of claim 4, wherein the postflush fluid comprises methanol,water, or combinations thereof.
 6. The method of claim 4, wherein thepack is left to harden for substantially 48 hours or less aftercontacting the pack with the postflush fluid.
 7. The method of claim 4,wherein the permeability of the pack after contacting the pack with thepostflush fluid is substantially 80% or less of a permeability of theunconsolidated material.
 8. A method for completing a well, the methodcomprising: flowing an unconsolidated material into a wellbore formed ina hydrocarbon-bearing subterranean zone; flowing a consolidation fluidinto the wellbore; at least partially consolidating the unconsolidatedmaterial within the wellbore using the consolidating fluid to form an atleast partially consolidated material; after at least partiallyconsolidating the unconsolidated material, dissolving at least a portionof the at least partially consolidated material to increase permeabilityof the at least partially consolidated material; and after dissolvingthe portion of the at least partially consolidated material, equalizinga flow of fluids through the at least partially consolidated material.9. The method of claim 8, wherein the consolidation fluid comprises aresin and a curing agent.
 10. The method of claim 8, wherein theunconsolidated material comprises sand, ceramic proppants, orcombinations thereof.
 11. The method of claim 10, wherein theconsolidation fluid and the unconsolidated material are flowed togetherinto the wellbore.
 12. The method of claim 10, wherein the consolidationfluid is flowed into the wellbore after flowing the unconsolidatedmaterial into the wellbore.
 13. The method of claim 10, furthercomprising contacting the at least partially consolidated material witha postflush fluid to increase the permeability of the at least partiallyconsolidated material.
 14. The method of claim 13, wherein the postflushfluid comprises an aqueous fluid, a solvent, or combinations thereof.15. The method of claim 14, wherein the postflush fluid comprisesmethanol, water, or combinations thereof.
 16. The method of claim 14,wherein the at least partially consolidated material is contacted withthe postflush fluid to increase permeability, and the at least partiallyconsolidated material is left to harden for substantially 48 hours orless.
 17. The method of claim 14, wherein the permeability of the atleast partially consolidated material after contacting the at leastpartially consolidated material with the postflush fluid issubstantially 80% or less of a permeability of the unconsolidatedmaterial.